|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
New NACE TEST METHOD! The purpose of this NACE International standard test method is to specify test methods and test conditions used to evaluate thermal properties, insulation values, and performance/integrity before and after thermal aging of insulative coatings. Testing for corrosion resistance is not included in this test method.
The primary intent of this standard is to specify test conditions that would provide a baseline evaluation – one that would allow direct performance comparisons between different insulative coatings. This standard is designed to have practical test procedures and limited test conditions. It also includes five mandatory appendixes that describe hot plate designs and thermal test setups, all of which are used in this standard test method.
This standard test method introduces new test methods to determine if, and at what rate, an insulative coating’s properties deteriorate with thermal aging. Test methods are given for both organic and inorganic based coatings. This standard test method is intended for use by facility owners, engineers, coating manufacturers, and other interested parties.
The purpose of this NACE International standard test method is to specify test methods and test conditions used to evaluate thermal properties, insulation values, and performance/integrity before and after thermal aging of insulative coatings. Testing for corrosion resistance is not included in this test method as that topic falls under the testing of the corrosion-resistant primers typically used with these coatings.
The primary intent of this standard is to specify test conditions that would give a baseline evaluation—one that would allow direct performance comparisons between different insulative coatings. This standard is designed to have practical test procedures and limited test conditions. It also includes Appendixes A–C (mandatory), which describe hot plate designs; and Appendixes D and E (mandatory) that describe thermal test setups, all of which are used in this standard test method.
This standard presents accepted methods and practices regarding the use of cathodic protection (CP) for the control of external corrosion on buried or submerged carbon steel, stainless steel, gray cast iron, ductile cast iron, copper, and aluminum piping systems at nuclear power plants. This standard may be useful at facilities other than nuclear power plants that contain complex networks of buried or submerged piping, which may be composed of more than one material and may or may not be grounded.
This standard addresses the design of CP systems in nuclear power plants for new piping systems and existing coated and uncoated piping systems. For each type of system, information is provided concerning the effects of grounding of the piping system on the design of the CP system. It also introduces design concepts for new piping systems that will assist in the design, operation, testing, or maintenance of a CP system.
This standard also presents accepted methods and practices for the installation, operation (including acceptance criteria), testing, and maintenance of CP systems in nuclear power plants. It presents criteria and procedures that may be used to determine the conditions under which a pipe or piping system need not be cathodically protected.
The primary NACE standard addressing cathodic protection (CP) of buried and submerged onshore piping systems is SP0169, “Control of External Corrosion on Underground or Submerged Metallic Piping Systems.”1 While the scope of SP0169 is primarily intended for onshore buried and submerged metallic piping systems, its major users include the oil and gas industry. Oil and gas transmission pipelines share certain characteristics which affect the design, installation, operation, and maintenance of CP systems.
The ability to design and manufacture thermodynamically stable nanocrystalline alloys via electrodeposition has enabled new materials with significantly improved mechanical and corrosion properties. These new alloys are particularly well-suited for applications throughout the electronics, transportation, aerospace and oil & gas industries. Key to improved corrosion performance is the supersaturated solid solution structure of these single-phase materials, eliminating microgalvanic corrosion common to multiphase alloys produced by traditional metallurgical methods. Furthermore, the electrodeposition process allows for the fine tuning of alloy composition and subsequently, mechanical & corrosion properties. We have previously prepared and demonstrated improved corrosion performance of Ni, Ag, and Al based nanocrystalline metal alloy coatings.1-3 that provide protection to corrosion prone materials such as Al, Cu, Fe and Mg. Herein we present structural, mechanical and immersion corrosion properties of a newly developed nanocrystalline NiMo alloy and provide comparisons to pure Ni, and previously developed NiW alloys targeted for commercial electronics applications.
Electrodeposited nickel has long been utilized as barrier layer for electronic connector and backplane applications to prevent the interdiffusion of gold and copper that leads to increased interface resistivity. Furthermore, nickel provides the increased wear performance necessary for the high number of connection cycles required in modern consumer electronic charging applications.
Previous work has shown that utilizing nanocrystalline NiW alloys significantly improves wear performance by increasing mechanical strength and hardness.1 This has allowed for a significant reduction in the necessary barrier layer thickness and a consequent reduction in the precious metal top layer of the connectors, leading to significant materials cost savings.
As the consumer electronics industry has moved to make products more water resistant, charging ports remain one of the few exposed areas of concern. Exposure to moisture, sweat, and other electrolytes in combination with an applied voltage during charging presents a significant corrosion concern.
Herein we present structural, mechanical and immersion corrosion properties of a newly developed nanocrystalline NiMo alloy and provide comparisons to pure Ni, and previously developed NiW alloys.
Galvanic corrosion is a serious issue that affects all aircraft platforms within the Naval Aviation Enterprise. Due to tolerance constraints or other design limitations, deposition of a metal film as a sacrificial coating is utilized as a method of protection. One such process is the deposition of aluminum onto high strength steel substrates via the ion vapor deposition (IVD) process. While this process is effective in mitigating corrosion, the facilities required to perform this task are highly specialized, and the deposition process is line-of-sight only. To address these shortfalls, we have developed a method allowing for the electrodeposition of aluminum onto stainless steel using ionic liquid chemistries. This increases the ease with which the system could be installed on-site while increasing the rate at which components could be repaired. To achieve this concept, a plating bath chemistry was adopted, focusing on utilizing ionic liquid mixtures to provide the chemical and electrochemical features necessary for aluminum deposition. This chemistry, coupled with an optimized pulse plating process, has led to a system which can successfully deposit high quality pure aluminum onto A286 stainless steel, providing protection against galvanically driven corrosion
Corrosion is a serious concern within naval aviation, impacting not only flight readiness but incurring high costs to mitigate corrosion occurrences.1 Due to the operational environment and the design of an aircraft, the risk of corrosion, especially galvanically driven corrosion, is high. Often times, design considerations require that dissimilar metals be in close proximity with each other in order to achieve certain strength or fatigue criteria. An example of this includes when high-strength steel fasteners are driven through aluminum ribs or skins. In order to prevent or reduce corrosion, various schemes have been devised to minimize the effect of these galvanic interactions by using primers, top coat paints, sealants, sacrificial coatings or a combination thereof.2 One such example of a sacrificial coating approach to reduce galvanic interaction is the use of the aluminum ion vapor deposition (IVD) process to coat stainless steel fasteners coupled with aluminum. However, this method requires highly-specialized equipment and specially trained operators to execute the process. The research presented herein is a proof-of-concept demonstration for a new method for aluminum deposition on CRES stainless steel fasteners, specifically A286. This research utilizes a tailored plating sequence and an ionic liquid mixture of 1-ethyl-3-methyl imidazolium chloride (EMIC), aluminum chloride and manganese chloride to accomplish the successful electrochemical deposition of aluminum on A286.
Kass, Michael D. (Oak Ridge National Laboratory) | Connatser, Raynella M. (Oak Ridge National Laboratory) | Lewis, Samuel A. (Oak Ridge National Laboratory) | Janke, Christopher J. (Oak Ridge National Laboratory) | Keiser, James R. (Oak Ridge National Laboratory) | Gaston, Katherine (National Renewable Energy Laboratory)
The compatibility of fueling infrastructure elastomers and plastics in bio-oil and diesel fuel was determined by measuring the volume swell. The bio-oil was produced via fast pyrolysis of woody feedstocks. The elastomer materials included fluorocarbons, acrylonitrile butadiene rubbers, neoprene, polyurethane, neoprene, styrene butadiene (SBR) and silicone. The plastic materials included polyphenylene sulfide (PPS), polyethylene terephthalate (PET), polytetrafluoroethylene (PTFE), polyvinylidene fluoride (PVDF), polyoxymethylene (POM), POM copolymer, high density polyethylene (HDPE), polybutylene terephthalate (PBT), polypropylene (PP), polyethylene terephthalate glycol (PETG), polythiourea (PTU), four nylon grades, and four thermosetting resins. The majority of the elastomer and plastic materials exhibited higher volume expansion in bio-oil than in diesel. These elastomers and plastics had high polarity values which more closely align with the polarities of the bio-oil versus the diesel fuel. Conversely, SBR, silicone, HDPE, and PP are relatively nonpolar and this matches the low polarity of the diesel fuel, which resulted in higher volume expansion in diesel, rather than the bio-oil for these four polymers.
This manuscript has been authored by UT-Battelle, LLC under Contract No. DE-AC05-00OR22725 with the U.S. Department of Energy. The United States Government retains and the publisher, by accepting the article for publication, acknowledges that the United States Government retains a non-exclusive, paid-up, irrevocable, world-wide license to publish or reproduce the published form of this manuscript, or allow others to do so, for United States Government purposes. The Department of Energy will provide public access to these results of federally sponsored research in accordance with the DOE Public Access Plan (http://energv.gov/downloads/doe-public-access-plan).
Fast pyrolysis-derived bio-oils are being evaluated as a renewable fuel for use in transportation, home heating, and energy production. Fast-pyrolysis consists of rapid heating (around 1000°C/sec) of biomass feedstock in the absence of oxygen. Liquid yields may reach 75% depending on feedstock type, reactor design and other processing variables. The resulting oils have high viscosity and water content relative to petroleum distillates. Because the feedstock is biomass (typically pelletized wood), these fuels provide a pathway toward reducing the dependency on foreign petroleum, while utilizing a cleaner, and renewable, resource. Bio-oil derived from fast pyrolysis of woody feedstock is being investigated as an alternative fuel. In order for these fuels to become acceptable and common, it is necessary that they are compatible with existing fuel systems and the associated infrastructure materials, both metals and polymers. The chemical profile of these fuels depends on the feedstock and can vary considerably (even among tree species). As a result, the composition of these oils can vary widely, but they usually consist of significant quantities of phenols, ketones, and other oxygenates (including short-chain carboxylic acids).
Specimens with binary and ternary concrete mixtures were prepared. The specimens were reinforced with a #3 rebar and have 0.75 cm concrete cover. Electromigration was used to accelerate chloride transport, this lasted anywhere between a week to a few months. The effect of rebar length under the reservoir and concrete composition was investigated. This paper presents the monitoring via linear polarization resistance and galvanostatic pulse to determine the corrosion current. The solution resistance and rebar potential were monitored for over 600 days. Corrosion in some cases initiated several weeks after removing the electromigration. Selected samples were terminated, only small corrosion spots were found.
The accumulation of corrosion products (once they exceed a certain volume and reach a critical penetration) during the corrosion propagation stage of corroding steel reinforcement embedded in concrete is known to cause cracks and eventually spalls. There have been several research efforts in which chlorides were added to the concrete mix of the specimens (so as to initiate corrosion right away) and then a current was applied to accelerate the corrosion1-5.
The magnitude of the applied current sometimes has been large enough to cause cracks after a few days to weeks. Some studies1,2,6,7 have suggested the application of a current of 100 μA/cm2, so as to replicate maximum-field observed values, and under these conditions, the current was applied from a few weeks to several months. Other studies have considered the presence of cracks of different sizes (incipient, 0.4 and 0.7 mm) on how the corrosion initiates and propagates8,9,10.
Sagues and collaborators6,7 have considered the effect of the length of the corroding site (assuming uniform corrosion around the whole rebar), rebar diameter and concrete cover to better understand the critical amount of corrosion products that could cause a crack. In these studies, the chlorides were added to the concrete mix when preparing the specimens. In partially-immersed bridges exposed to a marine environment, the chloride ions penetrate from the surface toward the reinforcement. Thus, the side of the rebar facing the chloride exposed concrete surface would reach the chloride threshold first and corrode. The initial corrosion site(s) can be as small as a small pit (e.g., < 1 mm diameter). Once corrosion has initiated, it is likely that the corroding site(s) would exert corrosion protection on the surrounding steel area (and the throwing power would depend on the concrete resistivity and moisture content) such that the next corroding site would be located some distance from the initial corroding site.
Corrosion problems related to crude refining became a dominant concern as crude oil refining expanded to serve global energy demands with concomitant economic benefits in the petroleum industry, and more so with the availability of ‘opportunity crudes’. Reducing oil production costs have continuously forced refineries to look for so-called “opportunity” or “alternate” crudes, which are usually lower quality, higher corrosivity crude oils with higher levels of naphthenic acids and sulfur compounds. Processing of these high acid, high sulfur crudes has engendered significant corrosion concerns in hot oil distillation units and associated piping systems.
Mitigating ‘opportunity crude’ corrosivity involves several strategies including improvement of the refining process of blending crudes, injection of inhibitors, de-acidification, utilization of materials with higher corrosion resistance, control of flow velocity and associated wall shear stress produced by the flow media, and finally optimization of in-service inspection and monitoring in oil refineries. This paper details a review, based on the experience of the authors in developing extensive naphthenic acid corrosivity data from a comprehensive Joint Industry Program (JIP), which investigates the influence of crude oil chemistry on naphthenic acid and sulfidic corrosion. Contributions of reactive sulfur chemistry to protectiveness and FeS scale formation, and the ability to resist naphthenic acid corrosion utilizing beneficial sulfur speciation as well as acid molecular weight, molecular structure, molecular boiling point as well as operational parameters of temperature, shear stress, and alloy metallurgy are addressed.
With the gradual depletion of conventional sweet oil resources, greater attention has been focused on more highly sour and acidic oil resources. Corrosion problems related to crude refining were identified early in the twentieth century as crude oil refining expanded to serve global energy demands with economic impact and benefits.1-7 The main constituents in the crude that cause corrosion are sulfur compounds, organic and inorganic chlorides, salt water, organic and inorganic acids and nitrogen that forms ammonia and cyanides. Reducing crude oil costs have continuously forced refineries to look for so-called “opportunity” or “alternate” crudes, which are usually low quality corrosive crude oils with high concentrations of naphthenic acids and sulfur compounds.5 Processing of these highly acidic and sulfur-containing crudes at high temperatures in refineries has promoted corrosion in hot oil distillation units and associated piping systems, and continues to be an important issue for the refining industry. It is reported that at least one crude unit corrosion issue, on a world-wide basis, occurs every week.8 Continued increases in acidic and sulfur-containing impurity content of feed stock is leading to a higher potential for corrosion damage. Mitigating this corrosion involves several strategies:5,9,10
Grouting deficiencies of post-tensioned tendons (PTT) have been associated with accelerated corrosion of the strands. A corrosion mitigation method by which a fluid is introduced via the interstitial spaces between the wires of a tendon’s strand has been recently used with promising results. Mechanistic experiments and multiphysics modeling simulation were used to examine the relative importance of alternative corrosion mitigating mechanisms, including oxygen transport limitation, cathodic and anodic inhibition, and ohmic resistance increase. Experimental results yielded a favorable prognosis that impregnating PTT would be successful in mitigating ongoing corrosion of steel strands. Both experiment and modeling pointed to a decrease of surface kinetics - lowered exchange current density for both anodic and cathodic reactions - as the likely main mitigation mechanism. Increasing grout resistivity and concentration polarization of the cathodic reaction did not seem to be dominant factors in mitigating corrosion.
Segmental bridges use Post Tensioned Tendons (PTT) made of high strength steel placed inside ducts filled with cement grout, which protects the steel from corrosion by maintaining an alkaline environment, hence promoting steel passivation. While grouting technology is usually reliable, incidents of severe corrosion distress and even complete failure of PTT have occurred.1-3 Some failures were attributed to local grout deficiencies in the form of voids due to bleed water accumulation, intrusion of external chloride and water through anchorages or defects in high density polyethylene (HDPE) ducts, possibly aggravated by carbonation of the grout and subsequent alkalinity decrease, as well as possible adverse galvanic coupling between anchorage components and the strand. Improvements in PTT practice were made for new structures to address those issues.3 However, despite those improvements, corrosion failures still have taken place4-7 emphasizing the need for backup corrosion control procedures. A promising approach has emerged recently based on pressurized tendon impregnation with a proprietary corrosion mitigating fluid that travels along the entire tendon through the minute interstices that exist between the individual wires in each strand.8-10 Impregnation is started at a convenient injection point at the anchor or at intermediate positions. The fluid is intended to provide cost-effective protection with otherwise minimal disruption. The technology has been used by Florida Department of Transportation (FDOT) for corrosion control circumstances that do not require tendon replacement.
For the design and materials selection of equipment in a chemical plant, the focus is often mainly on the “chemicals” side but it is often water (steam or cooling water) that causes the corrosion issues in many cases. This paper presents two cases that demonstrate poor design and non-optimized materials selection, causing severe corrosion and cracking issues. In both cases, the equipment is a fixed tubesheet type of heat exchangers (one is vertical, and another is horizontal) and the materials are mainly 300 series stainless steels. These two cases also demonstrate that such premature failures could be prevented by either design or proper materials selection.
Materials selection is very critical for the reliability of the asset. Equipment design also plays an important role in optimizing the use of materials properties. It is important to consider all aspects in terms of materials selection.
Additionally, the experiences, lessons learnt and general practices from other industries should always be accompanied with understandings of the corrosion/damage mechanisms in specific service environments. As demonstrated in Case 1, the experiences and practices in power industry are very valuable for some chemical applications.
Engineers, especially materials/corrosion engineers should have all bases covered when including design in order to select suitable materials for specific applications. The following are two cases that demonstrate how both inappropriate materials selection and improper design contributed to the failures.
CASE 1 - PREMATURE FAILURE OF VERTICAL HEAT EXCHAGER TUBES
This case study covers two identical shell and tube heat exchangers installed in a chemical plant and operated in parallel. The heat exchangers are vertical with fixed tubesheets. A process chemical (proprietary) in vapor state at about 420°C flows in the top of tubes side and are cooled by the water (steam) in the shell side (refer to table 1 for some additional details on the design data). The water (steam) flows in the bottom and moves out from the riser. This equipment can be treated as a steam generator.
Mechanical properties of the corrosion product layers as well as corrosion mechanisms need to be studied for better prediction of general and localized corrosion and to develop a holistic understanding of corrosion mechanisms in upstream oil and gas pipelines. Various ongoing research efforts have focused on the topic of sour corrosion mechanisms, while minimal attention has been paid to ascertaining the mechanical properties of the iron sulfide layers developed in these environments. The effects of fluid flow (i.e. erosion/corrosion, wall shear stress) as well as the impact of different operations (i.e. wellbore cleaning, wireline tools) on the internal pipeline wall, may lead to partial removal of corrosion product layers. This is an important topic, since mechanical damage of protective iron sulfide layers may lead to localized corrosion. To investigate the magnitude of stress required to damage iron sulfide layers up to the point of exposing the substrate, well-defined iron sulfide layers were developed in a 4-liter glass cell and the mechanical properties of the layers, such as hardness and adhesive strength, were investigated using a mechanical tester. To develop the iron sulfide layer, UNS G10180 carbon steel specimens were exposed to a 1 wt.% NaCl solution at pH of 6.0, and 0.1bar H2S (in a mixture with N2). FeS layers were developed at two solution temperatures, 30°C and 80°C, and the hardness and interfacial shear strength of the layers formed after 1 day and 3 days of exposure were investigated. The morphological characteristics of the FeS layers under investigation were examined by conducting SEM and cross-sectional analysis. XRD analysis confirmed mackinawite as the phase of the iron sulfide layer. While the interfacial shear strength of this mackinawite layer was found to be 5 magnitudes higher than the maximum flow related shear stress typically encountered in oil and gas operations, the integrity may still be compromised if these layers are subjected to other mechanical impacts (cavitation, droplet impingement) that may occur during production.